Known substations in high and medium-voltage power networks can include primary devices such as electrical cables, lines, bus bars, disconnectors, circuit breakers, power transformers and instrument transformers, which are generally arranged in switch yards and/or bays. These primary devices can be operated in an automated manner via a Substation Automation (SA) system. The SA system can include secondary devices, among which Intelligent Electronic Devices (IED) responsible for protection, control and monitoring of the primary devices. The secondary devices can be hierarchically assigned to a station level or a bay level of the SA system. The station level can include a supervisory computer having an Operator Work Station (OWS) with a Human-Machine Interface (HMI) and running a station-level Supervisory Control And Data Acquisition (SCADA) software, as well as a gateway that communicates the state of the substation to a Network Control Centre (NCC) and receive commands from it. IEDs on the bay level, also termed bay units, in turn can be connected to each other as well as to the IEDs on the station level via an inter-bay or station bus primarily serving the purpose of exchanging commands and status information.
A communication standard for communication between the secondary devices of a substation has been introduced by the International Electrotechnical Committee (IEC) as part of the standard IEC 61850 entitled “communication networks and systems in substations”. For non-time critical report messages, section IEC 61850-8-1 specifies the Manufacturing Message Specification (MMS, ISO/IEC 9506) protocol based on a reduced Open Systems Interconnection (OSI) protocol stack with the Transmission Control Protocol (TCP) and Internet Protocol (IP) in the transport and network layer, respectively, and Ethernet and/or RS-232C as physical media. For time-critical event-based messages, such as trip commands, IEC 61850-8-1 specifies the Generic Object Oriented Substation Events (GOOSE) directly on the Ethernet link layer of the communication stack. SA systems based on IEC61850 are configured by means of a standardized configuration representation or formal system description called Substation Configuration Description (SCD).
The protection lockout function is a protection related function which prohibits a re-close of tripped circuit breakers until an authorized person has explicitly removed the lockout, e.g. after having inspected the switch yard and the secondary equipment to verify that the cause of the preceding protection trip has been removed. The lockout function can be used for transformer protection trips, bus bar trips and breaker failure trips. The following functional specifications to be fulfilled include the following:                Distribution to multiple relays that control affected breakers.        Presentation of state to local and remote operators.        Standard operating procedure to clear the lockout.        Non volatile state—the lockout state can be stored in a way independent of power availability.        Independent handling of multiple lockouts of different protection functions on one and the same breaker.        
This function can be solved by using bi-stable relays in the closing circuit of the circuit breakers, which are set by the protection trip and generally reset manually. For each protection function respective protection zone which may trip the circuit breaker a separate bi-stable relay can be provided at the breaker. However, for process bus based solutions, where the circuit breaker can be controlled by some electronics integrated into it, an electronic reset of the lockout function would be preferred over a bi-stable relay.
FIG. 1 schematically shows an electronic lockout relay in accordance with a known implementation; and
The introduction of IEC 61850 with the GOOSE real time services offers the opportunity to replace the wiring to the circuit breakers by Ethernet based serial communication. The article (presented at Distributech 2009 Feb. 3) entitled “The Application of IEC 61850 to Replace Auxiliary Devices Including Lockout relays” by R. Brantley, K. Donahoe, J. Theron and E. Udren, and available at the time of filing from <<www.ge-energy.com/prod_serv/plants_td/en/downloads/gtr_aiecradlrp.pdf>>, proposes a communication bus based solution as illustrated in FIG. 1. The lockout function can be implemented in the breaker IEDs 13 for each breaker, and blocks the Circuit Breaker Close (CC) path. It can be triggered by the transformer (differential) protection function implemented in a transformer protection IED 11, and can be manually reset e.g. from a button or menu in the transformer protection IED 11. The trip command can be transferred via a serial bus 12. In addition to the lockout of the transformer protection function, the breaker controlled by IED 13 can also be tripped with lockout from a breaker failure function or a bus bar protection function, needing additional lockout relays (RS-Flipflops) and making the logic at the close circuit more complex. This kind of configuration implemented via a bus, e.g. based on IEC 61850 communication protocols, therefore needs complex engineering to “logically wire” the trip signals across the bus, couple the lockout relays to the breakers close circuit, and also to show the lockout state of the system to the operator.
A protection function protects some primary object, such as a line, a transformer, or a busbar. A fault on the object can be cleared by opening all circuit breakers surrounding this object and defining a so-called protection zone. Zones are electrically connected parts of the switchyard, which in general are limited by open disconnectors and open or closed circuit breakers. In case of a breaker failure protection being triggered by a failure of a particular circuit breaker, the trip is delegated to the circuit breakers of the protection zones connected to the left and right of the failed circuit breaker. Any closed circuit breaker is within two protection zones, one at its left side and one at its right side. The relation between circuit breakers and protection zones can be static as in ring configurations and 1½ breaker configurations, or is dynamically determined from the switchyard topology at single line level and by the current state of all disconnectors e.g., in case of double bus bar configurations.
Hence a circuit breaker needs at least two lockout relays, as long as redundant protection is not considered. As the breaker failure function will normally trip both zones right and left of a circuit breaker, a distinction between breaker failure protection and object related protection on behalf of an adjacent piece of primary equipment (transformer, line, bus bar) might specify another lockout relay instance. Lockout reset will have to be arranged for on each relay instance separately. In a known approach the trips from each zone should be physically or, with process bus, logically wired to all concerned breakers in a zone. For static configurations this might get complex if more than two breakers belong to a zone boundary. For dynamic zones this gets even more complex or nearly impossible.
EP 1819022 A1 aims at minimizing the potential damage caused by the failure of a single central Intelligent Electronic Device (IED) responsible for calculating, assigning and storing information about switchyard zones of a high or medium voltage switchyard including switchyard elements such as switches and connectivity nodes interconnected by lines. To this end, a distributed switchyard zone management is introduced, having a distributed storage of the knowledge about the switchyard zones with assignments of individual switchyard elements or components to the various switchyard zones being stored on several IEDs. The switchyard zones can be either protection zones or equipotential zones, wherein the first have a number of switchyard elements that are to be isolated simultaneously in case of a failure of a primary device. The boundary or circumference of a protection zone can be defined by circuit breakers and open disconnectors. Specific ways of distributed zone calculation and reset message passing are likewise disclosed.